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Water injection for oil displacement is one of the most effective ways to develop fractured-vuggy carbonate reservoirs. With the increase in the number of rounds of water injection, the development effect gradually fails. The emergence of high-pressure capacity expansion and water injection technology allows increased production from old wells. Although high-pressure capacity expansion and water injection technology has been implemented in practice for nearly 10 years in fractured-vuggy reservoirs, its mechanism remains unclear, and the water injection curve is not apparent. In the past, evaluating its effect could only be done by measuring the injection-production volume. In this study, we analyze the mechanism of high-pressure capacity expansion and water injection. We propose a fluid exchange index for high-pressure capacity expansion and water injection and establish a discrete model suitable for high-pressure capacity expansion and water injection curves in fractured-vuggy reservoirs. We propose the following mechanisms: replenishing energy, increasing energy, replacing energy, and releasing energy. The above mechanisms can be identified by the high-pressure capacity expansion and water injection curve of the well HA6X in the Halahatang Oilfield in the Tarim Basin. By solving the basic model, the relative errors of Reservoirs I and II are found to be 1.9% and 1.5%, respectively, and the application of field examples demonstrates that our proposed high-pressure capacity expansion and water injection indicator curve is reasonable and reliable. This research can provide theoretical support for high-pressure capacity expansion and water injection technology in fracture-vuggy carbonate reservoirs.

This paper expounds the basic principles and structures of the whole petroleum system to reveal the pattern of conventional oil/gas – tight oil/gas – shale oil/gas sequential accumulation and the hydrocarbon accumulation models and mechanisms of the whole petroleum system. It delineates the geological model, flow model, and production mechanism of shale and tight reservoirs, and proposes future research orientations. The main structure of the whole petroleum system includes three fluid dynamic fields, three types of oil and gas reservoirs/resources, and two types of reservoir-forming processes. Conventional oil/gas, tight oil/gas, and shale oil/gas are orderly in generation time and spatial distribution, and sequentially rational in genetic mechanism, showing the pattern of sequential accumulation. The whole petroleum system involves two categories of hydrocarbon accumulation models: hydrocarbon accumulation in the detrital basin and hydrocarbon accumulation in the carbonate basin/formation. The accumulation of unconventional oil/gas is self-containment, which is microscopically driven by the intermolecular force (van der Waals force). The unconventional oil/gas production has proved that the geological model, flow model, and production mechanism of shale and tight reservoirs represent a new and complex field that needs further study. Shale oil/gas must be the most important resource replacement for oil and gas resources of China. Future research efforts include: (1) the characteristics of the whole petroleum system in carbonate basins and the source-reservoir coupling patterns in the evolution of composite basins; (2) flow mechanisms in migration, accumulation, and production of shale oil/gas and tight oil/gas; (3) geological characteristics and enrichment of deep and ultra-deep shale oil/gas, tight oil/gas and coalbed methane; (4) resource evaluation and new generation of basin simulation technology of the whole petroleum system; (5) research on earth system – earth organic rock and fossil fuel system – whole petroleum system.

Based on core data, physical properties, well logging, gas testing, composition, and helium distribution from 13 newly drilled wells, in combination with regional tectonic evolution, depositional background, and typical gas reservoir profiles, helium-rich gas reservoirs geology characteristics and main controlling factors have been explored. The results show that three gas reservoirs formed from bottom to top, i.e., granite and metamorphite fractured reservoir in the basement, tight sandstone structural reservoirs in the Devonian, and huge continuous carbonate reservoirs in the Lower Carboniferous. Fractures developed on structural points control high-production, and gas is prominently displayed in low structural areas. The dry gas exhibits richness in helium, with decreasing helium content from the basement to the Carboniferous. The pre-Devonian large-scale granite and metamorphite basement serve as the primary helium source, while the high-gamma sandstones of the Devonian and the Carboniferous act as secondary sources. Fractures play a dual role, being filled up and conducting in two ways: gas from the Carboniferous source rocks migrates downward, and helium migrate upward. Thick interbedded gypsum-tight limestone on top of the Lower Carboniferous act as the regional caprock, effectively preserving the helium-rich gas reservoirs.

The phenomenon of carbon isotopic fractionation, induced by the transport of methane in tight sedimentary rocks through processes primarily involving diffusion and adsorption/desorption, is ubiquitous in nature and plays a significant role in numerous geological and geochemical systems. Consequently, understanding the mechanisms of transport-induced carbon isotopic fractionation both theoretically and experimentally is of considerable scientific importance. However, previous experimental studies have observed carbon isotope fractionation phenomena that are entirely distinct, and even exhibit opposing characteristics. At present, there is a lack of a convincing mechanistic explanation and valid numerical model for this discrepancy. Here, we performed gas transport experiments under different gas pressures (1–5 MPa) and confining pressures (10–20 MPa). The results show that methane carbon isotope fractionation during natural gas transport through shale is controlled by its pore structure and evolves regularly with increasing effective stress. Compared with the carbon isotopic composition of the source gas, the initial effluent methane is predominantly depleted in 13C, but occasionally exhibits 13C enrichment. The carbon isotopic composition of effluent methane converges to that of the source gas as mass transport reaches a steady state. The evolution patterns of the isotope fractionation curve, transitioning from the initial non-steady state to the final steady state, can be categorized into five distinct types. The combined effect of multi-level transport channels offers the most compelling mechanistic explanation for the observed evolution patterns and their interconversion. Numerical simulation studies demonstrate that existing models, including the Rayleigh model, the diffusion model, and the coupled diffusion-adsorption/desorption model, are unable to describe the observed complex isotope fractionation behavior. In contrast, the multi-scale multi-mechanism coupled model developed herein, incorporating diffusion and adsorption/desorption across multi-level transport channels, effectively reproduces all the observed fractionation patterns and supports the mechanistic rationale for the combined effect. Finally, the potential carbon isotopic fractionation resulting from natural gas transport in/through porous media and its geological implications are discussed in several hypothetical scenarios combining numerical simulations. These findings highlight the limitations of carbon isotopic parameters for determining the origin and maturity of natural gas, and underscore their potential in identifying greenhouse gas leaks and tracing sources.

Based on the recent oil and gas discoveries and geological understandings on the ultra-deep strata of sedimentary basins, the formation and occurrence of hydrocarbons in the ultra-deep strata were investigated with respect to the processes of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation, and key issues in ultra-deep oil and gas exploration were discussed. The ultra-deep strata in China underwent two extensional-convergent cycles in the Meso-Neoproterozoic Era and the Early Paleozoic Era respectively, with the tectonic-sedimentary differentiation producing the spatially adjacent source-reservoir assemblages. There are diverse large-scale carbonate reservoirs such as mound-beach, dolomite, karst fracture-vug, fractured karst and faulted zone, as well as over-pressured clastic rock and fractured bedrock reservoirs. Hydrocarbons were accumulated in multiple stages, accompanied by adjusting and finalizing in the late stage. The distribution of hydrocarbons is controlled by high-energy beach zone, regional unconformity, paleo-high and large-scale fault zone. The ultra-deep strata endow oil and gas resources as 33% of the remaining total resources, suggesting an important successive domain for hydrocarbon development in China. The large-scale pool-forming geologic units and giant hydrocarbon enrichment zones in ultra-deep strata are key and promising prospects for delivering successive discoveries. The geological conditions and enrichment zone prediction of ultra-deep oil and gas are key issues of petroleum geology.

Based on the oil and gas exploration practice in the Songliao Basin, combined with the latest exploration and development data such as seismic, well logging and geochemistry, the basic geological conditions, oil and gas types and distribution characteristics, reservoir-forming dynamics, source-reservoir relationship and hydrocarbon accumulation model of the whole petroleum system in shallow and medium strata in the northern part of Songliao Basin are systematically studied. The shallow–medium strata in northern Songliao Basin have the conditions for the formation of whole petroleum system, with sufficient oil and gas sources, diverse reservoir types and well-developed transport system, forming a whole petroleum system centered on the source rocks of the Cretaceous Qingshankou Formation. Different types of oil and gas resources in the whole petroleum system are correlated with each other in terms of depositional system, lithologic association and physical property changes, and they, to a certain extent, have created the spatial framework with orderly symbiosis of shallow–medium conventional oil reservoirs, tight oil reservoirs and shale oil reservoirs in northern Songliao Basin. Vertically, the resources are endowed as conventional oil above source, shale oil/tight oil within source, and tight oil below source. Horizontally, conventional oil, tight oil, interlayer-type shale oil, and pure shale-type shale oil are developed in an orderly way, from the margin of the basin to the center of the depression. Three hydrocarbon accumulation models are recognized for the whole petroleum system in northern Songliao Basin, namely, buoyancy-driven charging of conventional oil above source, retention of shale oil within source, and pressure differential-driven charging of tight oil below source.

Based on the analysis of Upper Paleozoic source rocks, source-reservoir-caprock assemblage, and gas accumulation characteristics in the Ordos Basin, the gas accumulation geological model of total petroleum system is determined. Then, taking the Carboniferous Benxi Formation and the Permian Taiyuan Formation and Shanxi Formation as examples, the main controlling factors of gas accumulation and enrichment are discussed, and the gas enrichment models of total petroleum system are established. The results show that the source rocks, faults and tight reservoirs and their mutual coupling relations control the distribution and enrichment of gas. Specifically, the distribution and hydrocarbon generation capacity of source rocks control the enrichment degree and distribution range of retained shale gas and tight gas in the source. The coupling between the hydrocarbon generation capacity of source rocks and the physical properties of tight reservoirs controls the distribution and sweet spot development of near-source tight gas in the basin center. The far-source tight gas in the basin margin is mainly controlled by the distribution of faults, and the distribution of inner-source, near-source and far-source gas is adjusted and reformed by faults. Generally, the Upper Paleozoic gas in the Ordos Basin is recognized in four enrichment models: inner-source coalbed gas and shale gas, inner-source tight sandstone gas, near-source tight gas, and far-source fault-transported gas. In the Ordos Basin, inner-source tight gas and near-source tight gas are the current focuses of exploration, and inner-source coalbed gas and shale gas and far-source gas will be important potential targets in the future.

Exploration and development practices prove that intracratonic strike–slip faults control the development of carbonate reservoirs and the enrichment of oil and gas in the Tarim Basin. Intracratonic strike–slip faults are characterized by short displacement, small throw and great burial depth, so there are still many controversies on their structural evolution and formation mechanisms. In order to settle these controversies, this paper firstly analyzes the geometric and kinematic characteristics of the intracratonic strike–slip faults in the central Tarim Basin. Then, based on extensive high-accuracy 3D seismic data and 2D seismic data, the formation and evolution process of the intracratonic strike–slip faults in the Tarim Basin are discussed deeply, and their genetic mechanisms are explored. Moreover, the following research results are obtained. First, the strike–slip faults in the study area have the characteristics of vertical stratification, plane zonation and segmentation along the strike. Second, the movement directions of the deep transpressional strike–slip faults are simple. The NE and NNE strike–slip faults are sinistral, and the NNW strike–slip faults are dextral. However, the shallow transtensional faults are more different in the movement direction. The strike–slip faults have displacements of 400–1500 m, and they are classified as intracratonic strike–slip faults with small slip distance. Third, the strike–slip faults were formed in the middle Caledonian, and some faults were reactivated in the late Caledonian–early Hercynian, late Hercynian, and Yanshanian–early Himalayan. The distribution of faults is different in different periods. Fourth, the formation of the strike–slip faults in the middle Caledonian is controlled by the basement heterogeneity and the compression action from the closure and subduction of the Proto-Tethys Ocean. The transtensional faults are R-shear branch faults or tensile break faults generated by the later activation of middle Caledonian strike-slip faults, and their formation is controlled by the subduction and closure of oceanic basins around the basins in different periods. In conclusion, the structural characteristics, formation & evolution and genetic mechanisms of intracratonic strike–slip faults are in close relation to oil and gas, where great benefit of oil and gas exploration and development is achieved. Besides the Tarim Basin, the Sichuan Basin and the Ordos Basin have similar geological and structural settings, so the studies on typical basins will surely enrich and complete the theories on the intracratonic strike–slip faults in domestic micro land blocks and multi-cycle basins and point out the direction for the discovery of more oil and gas resource.

The successful development of unconventional hydrocarbons has significantly increased global hydrocarbon resources, promoted the growth of global hydrocarbon production and made a great breakthrough in classical oil and gas geology. The core mechanism of conventional hydrocarbon accumulation is the preservation of hydrocarbons by trap enrichment and buoyancy, while unconventional hydrocarbons are characterized by continuous accumulation and non-buoyancy accumulation. It is revealed that the key of formation mechanism of the unconventional reservoirs is the self-sealing of hydrocarbons driven by intermolecular forces. Based on the behavior of intermolecular forces and the corresponding self-sealing, the formation mechanisms of unconventional oil and gas can be classified into three categories: (1) thick oil and bitumen, which are dominated by large molecular viscous force and condensation force; (2) tight oil and gas, shale oil and gas and coal-bed methane, which are dominated by capillary forces and molecular adsorption; and (3) gas hydrate, which is dominated by intermolecular clathration. This study discusses in detail the characteristics, boundary conditions and geological examples of self-sealing of the five types of unconventional resources, and the basic principles and mathematical characterization of intermolecular forces. This research will deepen the understanding of formation mechanisms of unconventional hydrocarbons, improve the ability to predict and evaluate unconventional oil and gas resources, and promote the development and production techniques and potential production capacity of unconventional oil and gas.

The discovery and large-scale exploration of unconventional oil/gas resources since 1980s have been considered as the most important advancement in the history of petroleum geology; that has not only changed the balance of supply and demand in the global energy market, but also improved our understanding of the formation mechanisms and distribution characteristics of oil/gas reservoirs. However, what is the difference of conventional and unconventional resources and why they always related to each other in petroliferous basins is not clear. As the differences and correlations between unconventional and conventional resources are complex challenging issues and very critical for resources assessment and hydrocarbon exploration, this paper focused on studying the relationship of formations and distributions among different oil/gas reservoirs. Drilling results of 12,237 exploratory wells in 6 representative petroliferous basins of China and distribution characteristics for 52,926 oil/gas accumulations over the world were applied to clarify the formation conditions and genetic relations of different oil/gas reservoirs in a petroliferous basin, and then to establish a unified model to address the differences and correlations of conventional and unconventional reservoirs. In this model, conventional reservoirs formed in free hydrocarbon dynamic field with high porosity and permeability located above the boundary of hydrocarbon buoyancy-driven accumulation depth limit. Unconventional tight reservoirs formed in confined hydrocarbon dynamic field with low porosity and permeability located between hydrocarbon buoyancy-driven accumulation depth limit and hydrocarbon accumulation depth limit. Shale oil/gas reservoirs formed in the bound hydrocarbon dynamic field with low porosity and ultra-low permeability within the source rock layers. More than 75% of proved reserves around the world are discovered in the free hydrocarbon dynamic field, which is estimated to contain only 10% of originally generated hydrocarbons. Most of undiscovered resources distributed in the confined hydrocarbon dynamic field and the bound hydrocarbon dynamic field, which contains 90% of original generated hydrocarbons, implying a reasonable and promising area for future hydrocarbon explorations. The buried depths of hydrocarbon dynamic fields become shallow with the increase of heat flow, and the remaining oil/gas resources mainly exist in the deep area of “cold basin” with low geothermal gradient. Lithology changing in the hydrocarbon dynamic field causes local anomalies in the oil/gas dynamic mechanism, leading to the local formation of unconventional hydrocarbon reservoirs in the free hydrocarbon dynamic field or the occurrence of oil/gas enrichment sweet points with high porosity and permeability in the confined hydrocarbon dynamic field. The tectonic movements destroy the medium conditions and oil/gas components, which leads to the transformation of conventional oil/gas reservoirs formed in free hydrocarbon dynamic field to unconventional ones or unconventional ones formed in confined and bound hydrocarbon dynamic fields to conventional ones.

Deep saline permeable sandstones have the potential to serve as sites for CO2 storage. However, unstable CO2 storage in pores can be costly and harmful to the environment. In this study, we used lattice Boltzmann (LB) simulations to investigate the factors that affect steady-state CO2–brine imbibition flow in sandstone pores, with a focus on improving CO2 storage efficiency in deep saline permeable sandstone aquifers. We extracted three representative element volumes (REVs) from a digital rock image of a sandstone core and selected a tighter REV in the upper subdomain so that its permeability would apparently be lower than that of the other two based on single-phase LB simulation for further analysis. The results of our steady-state LB simulations of CO2–brine imbibition processes in the tighter REV under four differential pressures showed that a threshold pressure gradient of around 0.5 MPa/m exists at a differential pressure of 200 Pa, and that higher differential pressures result in a greater and more linear pressure drop and stronger channelization after the flow are initiated. Furthermore, we conducted simulations over a range of target brine saturations in the tighter REV at the optimal differential pressure of 400 Pa. Our findings showed that the relative permeability of CO2 is greatly reduced as the capillary number falls below a certain threshold, while the viscosity ratio has a smaller but still significant effect on relative permeability and storage efficiency through the lubrication effect. Wettability has a limited effect on the storage efficiency, but it does impact the relative permeability within the initial saturation range when the capillary number is low and the curves have not yet converged. Overall, these results provide micro-scale insights into the factors that affect CO2 storage efficiency in sandstones.

Some major hydrocarbon-bearing basins are rich in shale with terrestrial facies in China, which may provide abundant terrestrial shale oil and gas resources. This work studied the Jurassic Lianggaoshan Formation in the Southeast Sichuan Basin of the upper Yangtze Region. Core samples were chosen for the total organic carbon content and mineral composition analyses to classify shale lithofacies. Afterward, pore connectivity, pore wettability, and shale oil mobility with different lithofacies were characterized by spontaneous imbibition, nuclear resonance, and centrifugation. Conclusions are as follows: the pore connectivity of organic-rich clay shale was mostly between moderate to good with oil-prone wettability and high mobile oil saturation. The organic-rich mixed shale has moderate to good pore connectivity, water-prone wettability, and the highest mobile oil saturation. Organic matter–bearing clay shale has bad to moderate pore connectivity. Meanwhile, its pore wettability covers oil wetting, mixed wetting, oil-prone wetting, and water-prone wetting. Its mobile oil saturation was moderate. Regarding organic matter–bearing mixed shale, the pore connectivity was bad to moderate with mixed-wetting pore wettability and moderate mobile oil saturation.

The discovery of unconventional hydrocarbon resources since the late 20th century changed geologists’ understanding of hydrocarbon migration and accumulations and provides a solution to energy shortage. In 2016, unconventional oil production in the USA accounted for 41% of the total oil production; and unconventional natural gas production in China accounted for 35% of total gas production, showing strong growth momentum of unconventional hydrocarbons explorations. Unconventional hydrocarbons generally coexist with conventional petroleum resources; they sometimes distribute in a separate system, not coexisting with a conventional system. Identification and prediction of unconventional resources and their potentials are prominent challenges for geologists. This study analyzed the results of 12,237 drilling wells in six representative petroliferous basins in China and studied the correlations and differences between conventional and unconventional hydrocarbons by comparing their geological features. Migration and accumulation of conventional hydrocarbon are caused dominantly by buoyance. We propose a concept of buoyance-driven hydrocarbon accumulation depth to describe the deepest hydrocarbon accumulation depth driven dominantly by buoyance; beyond this depth the buoyance becomes unimportant for hydrocarbon accumulation. We found that the buoyance-driven hydrocarbon accumulation depth in petroliferous basins controls the different oil/gas reservoirs distribution and resource potentials. Hydrocarbon migration and accumulations above this depth is dominated by buoyancy, forming conventional reservoirs in traps with high porosity and permeability, while hydrocarbon migration and accumulation below this depth is dominated by non-buoyancy forces (mainly refers to capillary force, hydrocarbon volume expansion force, etc.), forming unconventional reservoirs in tight layers. The buoyance-driven hydrocarbon accumulation depths in six basins in China range from 1200 m to 4200 m, which become shallower with increasing geothermal gradient, decreasing particle size of sandstone reservoir layers, or an uplift in the whole petroliferous basin. The predicted unconventional resource potential below the buoyance-driven hydrocarbon accumulation depth in six basins in China is more than 15.71 × 109 t oil equivalent, among them 4.71× 109 t reserves have been proved. Worldwide, 94% of 52,926 oil and gas reservoirs in 1186 basins are conventional reservoirs and only 6% of them are unconventional reservoirs. These 94% conventional reservoirs show promising exploration prospects in the deep area below buoyance-driven hydrocarbon accumulation depth.

China's continental oil and gas geological theory occupies an important academic position in the world's academic circle of petroleum geology. China's oil and gas resources are dominated by continental resources. Chinese geologists have successfully explored and developed complex continental oil and gas, and developed a continental oil and gas geological theory system. This paper summarizes the development history and theoretical achievements of continental oil and gas geological theory since the 1940s and proposes that the development of this theory should be divided into three stages (i.e., proposal, formation and development). The China's continental oil and gas geological theory has formed a basically perfect theoretical system consisting of five parts, i.e., continental basin structure theory, continental basin sediments and reservoirs theory, continental oil generation theory, continental oil and gas accumulation theory, and continental sandstone oil and gas field development geology. As an advanced geological theory, it has a universal significance globally. This paper focuses on the major discoveries of oil and gas exploration and development and the production growth in the basins of the Central and Western China in the past 30 years as well as the major advances in the continental oil and gas geological theory, including the continental basin tectonics of Central and Western China under the compression background, special reservoir geology such as various types of lake basin sedimentary systems and deep conglomerate, new fields of continental hydrocarbon generation such as coal-generated hydrocarbons, continental oil and gas enrichment regularity such as foreland thrust belts and lithologic-stratigraphic reservoirs, continental unconventional oil and gas geology and continental low-permeability oil and gas development geology. These major advances have greatly developed and enriched the continental oil and gas geological theory and become an important part of it. Key words: continental petroleum geology, Central and Western China basins, foreland basin thrust belt, theoretical development stage

The southern Junggar Basin has enormous hydrocarbon mainly from the Jurassic and Permian source rocks, which indicated the importance of exploration of the deeply buried Jurassic reservoirs, therefore, the study of the deeply buried Upper Jurassic Qigu Formation (J3q) reservoirs in Well DS-1 in the Dushanzi anticline was carried out through microscopic observation and measurement, nuclear magnetic resonance (NMR), scanning electron microscopy (SEM) and high pressure mercury injection. Results showed that the main reservoir storage spaces in the deeply buried Upper Jurassic Qigu Formation reservoirs were fractures and dissolved pores. The J3q reservoirs with low porosity and permeability values of 0–12% and (0–5) × 10−3μm2 respectively, were generally tight. According to the mercury injection data, heterogeneity existed in the deeply buried Qigu Formation reservoirs with inhomogeneous pores and changeable sizes of pores throats. Pores and pore throats in the silt-fine sandstones of the lower Qigu Formation (J3q1) were more big and wide respectively than that in the argillaceous siltstones of the upper Qigu Formation (J3q3). Reservoirs in J3q1 had more mobile fluid and better conductivities than reservoirs in J3q3. The strong compaction and multistage diagenesis resulted in the tight J3q reservoirs. Anhydrite and quartz cementation, and various authigenetic minerals (e.g. hematite, kaolinite, illite/smectite formation, illite, chlorite and zeolite) filled in the pores. The homogenization temperature of brine inclusions (63.1–161.7 °C) in quartz overgrowth indicated the quartz had grown since the late Eocene. Due to the Tian Shan reactivity in the Late Cenozoic, the structure fractures were developed and promoted dissolution by oil and formation water in the reservoirs of J3q1. Keywords: Tight reservoirs evolution, Heterogeneity, Fluid inclusion, Structure fractures, Qigu Formation, The Dushanzi anticline, Southern Junggar Basin

Great changes of the global energy industry have been caused by the rapid development of unconventional oil and gas. It is necessary to deeply consider the profound influence of the unconventional oil and gas revolution on the classical petroleum geology theory and to review geological conception of oil and gas accumulation elements and theoretic framework of petroleum system, giving the petroleum geology a new academic connotation. The author summarizes the significant progresses of global unconventional oil and gas exploration and development, and points out that the unconventional oil and gas revolution not only has a significant economic significance of oil and gas resource increment, but also brings great innovation to the theory of petroleum geology, thus having important scientific significances. This paper summarizes the core contents of four aspects of hydrocarbon generation, reservoir, distribution and development in classical petroleum geology, and comprehensively reviews the five important nodes in the developmental history of petroleum geology, which include anticline and trap theory, hydrocarbon generation from organic matter and petroleum system theory, continental petroleum geology, marine deepwater petroleum geology, continuous hydrocarbon accumulation and unconventional petroleum geology theory. Unconventional oil and gas has made a great breakthrough to classical petroleum geology on the basic theoretical concepts such as trap, reservoir, caprock, resource distribution, and enrichment, thereby promoting the basic research on petroleum geology to transform into the whole process of hydrocarbon generation, whole type of reservoir, and whole genetic mechanism, deepening unconventional petroleum geology theory, promoting the development and reconstruction of petroleum geology system, representing great significances to the strategic development from conventional to unconventional oil and gas in China or even in the world. Key words: petroleum geology, unconventional petroleum geology theory, continuous hydrocarbon accumulation, tight oil and tight gas, shale oil and shale gas, oil and gas production

Abstract: Oil and gas currently still hold a leading role in the global energy mix. The recent drastic increase in unconventional oil and gas production contributes significantly to strike a balance between the global demand and supply of oil and gas. However, a range of important fundamental questions about the unconventional oil and gas resources have not been adequately answered. Little is known about the distribution and accumulation patterns, as well as the exploration and development characteristics of unconventional oil and gas. The current status of global oil and gas exploration was reviewed and four key theoretical issues regarding the unconventional oil and gas geology were identified: (1) the traditional concept and definition of “petroleum system” needs to be revisited. The concept of a “holistic-process accumulation” model of a “total petroleum system” in petroliferous basins was proposed to analyze the unconventional hydrocarbon accumulation mechanisms from four key aspects of quantitative studies on hydrocarbon generation–expulsion–migration–accumulation processes. (2) The second issue is related to fine-grained sedimentary system and sedimentary facies of tight reservoirs. Through analyzing the relationship between fine-grained sediments and unconventional hydrocarbon accumulation, three research integration areas were put forward. (3) The third issue is on the micro-nano pore system and fluid phase behavior in shales and tight reservoirs. Five aspects of micro-nano pore system were identified to focus on unconventional hydrocarbon research, and the characteristics of micro-nano pore development and fluid phase behavior in micro-nanopores were elucidated. (4) The fourth issue is related to unconventional hydrocarbon accumulation patterns and resource evaluation. Based on the characteristics of unconventional hydrocarbon accumulation, an evaluation system for unconventional hydrocarbon resources was established and optimized. Key words: energy consumption, unconventional hydrocarbons, exploration status, petroleum system, tight reservoirs, micro-nano pore system

There are successes and failures in the exploration of marine shale gas in South China. In some shale gas plays with great basis for hydrocarbon generation, a phenomenon exists that gas loggings reflect low gas bearing in some of the wells and the gas is dominated by nitrogen rather than hydrocarbon gas. The study of nitrogen concentration in shale gas contributes to solve the question that how shale gas diffuses in complex tectonic areas, which helps to figure out the preservation requirements and accumulation mechanisms of shale gas and avoid exploration crisis. This study focused on the lower Cambrian shale in Xiuwu Basin, Lower Yangtze Region, with emphasis on the well Jiangye-1, using gas component analysis, stable nitrogen isotope analysis, overburden permeability tests in parallel and perpendicular directions, and FIB-HIM experiments, also combining with core description, outcrop observation, and seismic interpretation to explore the causes of the high-content nitrogen and low-content hydrocarbon in the lower Cambrian shale gas. The results show that the nitrogen of the lower Cambrian shale in Xiuwu Basin is derived from the atmosphere and the deep crust-upper mantle. The bedding planes and the detachment layer at the bottom of the lower Cambrian compose the lateral pathways, and the widespread deep faults are the vertical pathways for shale gas migration and diffusion. Combining these two, an effective pathway network was built, favorable to gas exchange between the shale gas interval and the atmosphere, partly leading to the concentration of nitrogen and the diffusion of hydrocarbon gas. In the Jurassic, the magmatic activities occurred frequently in the surrounding areas, which not only brought nitrogen from the deep crust-upper mantle but also increased the value of paleo-heat flow even though the basin began to uplift, which promoted the graphitization of organic matter and the collapse of organic pores and accelerated the loss of shale gas. Based on the study above, an explanation model was summarized to expound the causes of high-content nitrogen and low-content hydrocarbon in shale gas plays near the plate-active region in Xiuwu Basin, Lower Yangtze Region.

The study of tectonics is one of the important aspects of shale gas preservation. It is vital for understanding how to determine the enrichment regularity of marine shale gas in anticlines. This paper focuses on typical shale blocks in the southern Sichuan Basin and shale in the Upper Ordovician and the Lower Silurian. In this study, triaxial unloading tests, permeability tests perpendicular and parallel to the stratification plane, FIB-HIM tests, and inclusion analyses are carried out with real drilling data. The enrichment regularity of marine shale gas in anticlines is studied by considering 2 aspects: the angle of the limbs and the burial depth. For anticlines with adjacent synclines, the migration regularity of shale gas is considered by 3 aspects: the dynamics, channels, and processes of migration. This study reveals that a limb angle greater than 120° reflects relatively good conditions for shale gas preservation, while limb angles lesser than 70° indicate relatively poor conditions. This study also suggests that during the process of uplift, large-scale concentrated fractures will form at a certain depth range and horizontal stress field, resulting in the large loss of shale gas. The regression equation of the fractured depth (H) and the horizontal stress (S) is presented as H=15.404S−754.41 (with a correlation coefficient R2=0.6834). The stratification plane and the organic pores form the migration channel of natural gas that is horizontal to the stratification plane in shale. Under the condition of both anticlines and contiguous synclines, shale gas escapes through fractures resulting from extrusion along the anticline and the uplift effect. In addition, driven by differences in the formation pressure coefficients, shale gas is capable of migrating in a short-distance stair-type style from synclines to the adjacent anticlines. Thus, if the drilling costs allow, the well locations should be placed in the more deeply buried synclines.

The upper Ordovician-lower Silurian shale has always been the main target of marine shale gas exploration in southern China. However, the shale gas content varies greatly across different regions. The organic matter content is one of the most important factors in determining gas content; therefore, determining the enrichment mechanisms of organic matter is an important problem that needs to be solved urgently. In this paper, upper Ordovician-lower Silurian shale samples from the X-1 and Y-1 wells that are located in the southern Sichuan area of the upper Yangtze region and the northwestern Jiangxi area of the lower Yangtze region, respectively, are selected for analysis. Based on the core sample description, well logging data analysis, mineral and elemental composition analysis, silicon isotope analysis, and TOC (total organic carbon) content analysis, the upper Ordovician-lower Silurian shale is studied to quantitatively calculate its content of excess silicon. Subsequently, the results of elemental analysis and silicon isotope analysis are used to determine the origin of excess silicon. Finally, we used U/Th to determine the characteristics of the redox environment and the relationship between excess barium and TOC content to judge paleoproductivity and further studied the mechanism underlying sedimentary organic matter enrichment in the study area. The results show that the excess silicon from the upper Ordovician-lower Silurian shale in the upper Yangtze area is derived from biogenesis. The sedimentary water body is divided into an oxygen-rich upper water layer that has higher paleoproductivity and a strongly reducing lower water that is conducive to the preservation of sedimentary organic matter. Thus, for the upper Ordovician-lower Silurian shale in the upper Yangtze region, exploration should be conducted in the center of the blocks with high TOC contents and strongly reducing water body. However, the excess silicon in the upper Ordovician-lower Silurian shale of the lower Yangtze area originates from hydrothermal activity that can enhance the reducibility of the bottom water and carry nutrients from the crust to improve paleoproductivity and enrich sedimentary organic matter. Therefore, for the upper Ordovician-lower Silurian shale in the lower Yangtze region, exploration should be conducted in the blocks near the junction of the two plates where hydrothermal activity was active.

Abstract: Tight oil refers to a petroleum play that occurs in a free or adsorbed state in source rocks or tight reservoir rocks (e.g., sandstone and carbonate rock) interbedded with or close to source rocks. Tight oil has generally not experienced large-scale, long-distance migration. According to such a definition and its characteristics, 10 key indices are proposed for tight oil resource evaluation in China. Tight oil reservoirs are divided into three groups in terms of porosity and permeability. Tight oil can be classified into three types according to the contact relationship between the tight oil reservoirs and source rocks, i.e., tight lacustrine carbonate oil, tight deep-lake gravity flow sandstones oil, and tight deep-lake deltaic sandstones oil. In China, tight oil resources are widely distributed and significant exploration discoveries have been achieved in the sixth member and seventh member of the Triassic Yanchang Formation in the Ordos Basin, the Permian Lucaogou Formation in the Junggar Basin, the Middle-Lower Jurassic strata of the Sichuan Basin, and the Cretaceous Qingshankou and Quantou Formations in the Songliao Basin. The total geological resources of tight oil in China assessed by using the “analog” method are estimated to be (10.67−11.15) ×109 tones. Taking into account of the future prospects of petroleum development, tight oil may become a realistic alternative to the conventional oil resources in China. Key words: tight oil, evaluation criteria, classification, reservoir characteristics, resource potential

As a result of complex tectonic background, shale gas in China exhibits differential enrichment. Choosing a favorable exploration target accurately is a crucial problem to be solved. In this study, the tests show that there is a superior transportation pathway within shale layer. Gas in the shale layer percolates much more in the direction parallel to the plane. Therefore, the accumulation pattern of shale gas indicates a complex tectonic background. Gas in the lower part of the structure diffuses and percolates in the vertical direction into the surrounding rock. Most gas percolates towards the high part of the structure in the direction parallel to the plane. When the shale was exposed, gas percolated along the parallel direction into the air. In the case of fracture development, if there is a reverse fault, gas would be enriched in the footwall. However, if there is an unsealed fault, it would become a pathway for gas migration. The above accumulation pattern was proved in several Areas. Also, this research presented a basis of evaluation units division. According to the buried depth, fractures, and structural position, Xiuwu Basin was divided into five evaluation units and Unit A3 is the most favorable exploration target.

Based on structural interpretation of the recent seismic data in central Sichuan Basin, combined with data of drilling and outcrops around the basin, this paper discusses the evolutional characteristics of unconformities at various stages in the Leshan-Longnüsi paleo-uplift, and studies the evolution of the paleo-uplift and its control on Sinian gas reservoir accumulation. Sinian, Paleozoic, Mesozoic and other major regional unconformities were developed in the Leshan-Longnüsi paleo-uplift. According to characteristics and denudation thickness of the unconformities, the paleo-uplift tectonic evolution is divided into four stages, namely, embryonic, developmental, stable burial, and finalization. The analysis of the effects of the tectonic evolution on the Sinian gas accumulation show that: (1) the unconformities controlled the development of ancient karst reservoirs relevant to paleo-weathering crust; (2) the tectonic evolution of the paleo-uplift controlled evolution of organic matter and hydrocarbon migration and accumulation; (3) morphological changes of the paleo-uplift controlled the formation and the mergence of structural traps. Key words: Sichuan Basin, paleo-uplift, Sinian strata, tectonic evolution, gas accumulation, unconformities, ancient karst

Based on analysis of the characteristics of unconventional hydrocarbon resources, this paper assesses the potential for unconventional hydrocarbons in China, summarizes the key technical progress in exploration and development, and discusses the prospects and developing strategies of unconventional hydrocarbons. The resources of unconventional oil and gas in China are abundant. The recoverable tight gas ranges from 8.8×1012 m3 to 12.1×1012 m3, the recoverable shale gas is from 15×1012 m3 to 25×1012 m3, the recoverable coalbed methane 10.9×1012 m3, the recoverable tight oil from 13×108 t to 14×108 t, and the recoverable shale oil 160×108 t. There is also some resource potential for oil sand. Such key techniques as the full-digital seismic exploration, low permeability and low resistivity reservoirs identification have been developed and their applications in oil and gas fields have achieved good results. Tight gas and tight oil are the most realistic resources to develop in China and the development and utilization of coalbed methane and shale gas are at a pioneer stage. In the next ten or twenty years, the production of unconventional hydrocarbon in China will increase considerably and play a major role in national hydrocarbon resources. Key words: unconventional hydrocarbon, resource potential, exploration and development technology, tight gas, tight oil, shale gas, coalbed methane

Organic matter is the material basis of hydrocarbon generation and the abundance of organic matter is a main factor of regional selection and evaluation in shale gas. Also the enrichment is influenced by sedimentary environments. Thus, it is important for the study on the geological factors controlling organic matter enrichment and further to provide scientific basis of regional selection and evaluation by organic matter enrichment area with analysis of the factors. In this paper, the Upper Ordovician–Lower Silurian shale from representative wells in the Upper-Lower Yangtze area is selected as the research object. The goal of this study is to quantitatively calculate the excess siliceous mineral content in shale siliceous minerals and determine the origin of excess silicon based on Al, Fe, and Mn elements; as well as to analyze the sedimentary organic matter enrichment mechanism based on the water body redox environment and bio-productivity. The results show that excess silicon from the Upper Ordovician–Lower Silurian shale in the Upper Yangtze area is biogenic and deposited in closed water bodies. On the one hand, the upper water body contains oxygen, which leads to higher bio-productivity. On the other hand, the lower water body has strong reducibility, which is conducive to sedimentary organic matter preservation. However, the excess silicon in the Upper Ordovician–Lower Silurian shale of the Lower Yangtze area is derived from hydrothermal solution. Hydrothermal activity can enhance the bottom water reducibility, and its nutrient elements can improve bio-productivity and enrich sedimentary organic matter. Therefore, the organic matter enrichment, which depends on the biological productivity and redox conditions, is controlled by the water closure in the Upper Yangtze and hydrothermal activities in the Lower Yangtze respectively. It led to a conclusion that in the process of regional selection and evaluation of shale gas in the Late Ordovician–Early Silurian, it is favorable in the area of relatively strong closure, which is the center of cratonic depression, in the Upper Yangtze and in the hydrotherm-active area, which is the plate connection of the Lower Yangtze and the Cathaysian, in the Lower Yangtze.

Shale oil production is vital for meeting the rising global energy demand, while primary recovery rates are poor due to the ultralow permeability. CO2 huff-n-puff can boost yields by enabling key enhanced oil recovery mechanisms. This review examines the recent research on mechanisms and formation factors influencing CO2 huff-n-puff performance in shale liquid reservoirs. During the soaking period, oil swelling, viscosity reduction and CO2-oil miscibility occur through molecular diffusion into shale nanopores. The main recovery mechanism during the puff period is depressurization with oil desorption and elastic energy release. The interplay between matrix permeability and fracture network directly determines the CO2 huff-n-puff performance. Nanopore confinement, wettability alterations, and heterogeneity also significantly impact the huff-n-puff processes, with controversial effects under certain conditions. This work provides an integrated discussion on the mechanistic insights and formation considerations essential for the advancement of CO2 huff-n-puff application in shale reservoirs. By synthesizing the recent research findings, we aim to spotlight the key challenges and opportunities in considering reservoirs for this process, thereby contributing to the advancement of CO2 huff-n-puff applications for enhanced oil recovery. [ABSTRACT FROM AUTHOR]

Despite the significant progress made in tight gas exploration and development in recent years, the understanding of the dynamic mechanisms of tight gas accumulation is still limited, and numerical simulation methods are lacking. In fact, the gap between theory and field application has become an obstacle to the development of tight gas exploration and development. This work sheds light on the dynamic mechanisms of hydrocarbon accumulation in tight formations from the aspect of capillary self-sealing theory by embedding calculation of pressure- and temperature-dependent capillary force in a pore network model. The microscale dynamic mechanisms are scaled up to the reservoir level by geological simulation, and the quantitative evaluation of reserves based on real geological sections is realized. From the results, several considerations are made to assist with resource assessment and sweet spot prediction. Firstly, the self-sealing effect of capillary in the micro-nano pore-throat system is at the core of tight sandstone gas accumulation theory; the hydrocarbon-generated expansion force is the driving force, and capillary force comprises the resistance. Furthermore, microscopic capillary force studies can be embedded into a pore network model and scaled up to a geological model using relative permeability curve and capillary force curve. Field application can be achieved by geological numerical simulations at the reservoir scale. Finally, high temperature and high pressure can reduce capillary pressure, which increases gas saturation and reserves. [ABSTRACT FROM AUTHOR]